The largest complex of geothermal power plants in the world (950 megawatts) is operated on dry steam taken from the Geysers area in Northern California, U.S.A. This steam is produced under a pressure of 120 psia with superheat up to 10.degree. F. and at a rate of about 17 million pounds per hour. The impurities present in the steam in significant amounts are listed in Table 1.
TABLE 1 ______________________________________ Amount (ppmw).sup.1 Contaminant Average Range ______________________________________ CO.sub.2 3000 300-6000 H.sub.2 S 220 70-570 NH.sub.3 100 10-330 CH.sub.4 200 H.sub.2 50 N.sub.2 50 B.sup.2 20 ______________________________________ NOTES: .sup.1 Parts per million by weight. .sup.2 Predominantly as boric acid.
Although desirable, removal of all of the listed contaminants is not essential. However, the plant maintenance problem caused by boric acid-derived deposits on turbine blades would make boric acid removal, prior to power extraction from the steam, a very desirable treatment. This can be done effectively by water scrubbing. Some superheat is lost in the scrubbing operation but the benefit of also removing H.sub.2 S can be gained if an alkaline reagent is added to the liquid.
Unfortunately, only part of the H.sub.2 S is removed by known alkaline scrubbing procedures. The H.sub.2 S content of the scubbed steam is still high enough to require further treatment of plant effluent streams to avoid emission problems. That is, the turbine exhaust is condensed by heat exchange with cool water, the non-condensibles are vented and the condensate is sent to a cooling tower. This results in partial evaporation and cooling of the unevaporated portion of the condensate. Most of the the cooled portion is used as the cool water supply to the condenser (the rest--about 0.18 lbs. per lb. of steam supply--constitutes the available process water for the complex). Part of the H.sub.2 S is vented with the non-condensibles and the rest is flashed off in the evaporation step. The emitted H.sub.2 S is generally diluted to non-toxic levels by the prevailing winds but still causes an odor problem for down-wind communities. The problem is particularly acute when a power plant must be shut down and the steam "stacked", i.e., vented directly to the atmosphere without further treatment.
State and local governments have enacted regulations including timetables for the development of one or more treatment methods which are capable of abating the problem (but are not prohibitively expensive). The need for a really effective method of removing H.sub.2 S from geothermal steam is thus clear.
Conventional wisdom is to the effect that alkaline scrubbing cannot be made more effective because the absorption equilibrium for H.sub.2 S in aqueous sodium hydroxide is unfavorable at the temperature of the produced steam (Geothermal Air Emission Characterization, Vol. II: Air Pollution Control Technology For Geothermal Power Plants; pp. 49-51, K. T. Semrau et al, Stanford Research International, Menlo park, Calif. EPA Contract No. 68-03-2661. (October 1980)). There is also the consideration that even if all the H.sub.2 S could be removed by alkaline scrubbing, this would be at the additional cost of the caustic which would be consumed by the relatively large content of CO.sub.2 in the steam. It is known (U.S. Pat. No. 2,747,962) that H.sub.2 S--even though more weakly acidic than CO.sub.2 --can be selectively removed from gaseous mixtures in a short-contact process which takes advantage of the fact that the rate of CO.sub.2 uptake by aqueous NaOH is significantly slower than the rate of H.sub.2 S uptake. However, at temperatures substantially higher than ambient, the latter difference in rates becomes so small that the desired selectivity of alkaline scrubbing for H.sub.2 S is lost.
The most effective prior art, alkaline scrubbing process for removal of H.sub.2 S from steam known to the present Applicants is that disclosed in U.S. Pat. No. 4,163,044. This process apparently is the one which has been experimentally used to treat the incoming steam at the Geysers Unit No. 12 (primarily for removal of boric acid and dust). Further treatment of the steam (downstream of the turbine) by other methods--such as the well known Stretford process--is necessary to reduce H.sub.2 S emissions to a currently acceptable level.
In the process of the '044 patent, the incoming steam is counter-currently contacted in an absorption tower with an aqueous NaOH solution which already contains a relatively high amount of sulfide species, as well as sulfite and sulfate species. The sulfide content in the sulfide-loaded, liquid effluent from the tower is then reduced by oxidation. A bleed portion of the treated effluent is discarded and makeup water and NaOH are added to the remainder, which is then recirculated to the tower for another absorption cycle. The oxidation is carried out on the entire effluent stream or, preferably, on a portion of it, from which the bleed is taken before it is recombined with the rest of the effluent. The oxidant used is H.sub.2 O.sub.2, the thermal instability of which necessitates cooling the effluent feed to the oxidizer (by heat exchange with the oxidized effluent stream exiting the oxidizer). The only indication in the patent as to how much of the H.sub.2 S can be removed by the disclosed process is the phrase " . . . thereby absorbing a significant portion of the hydrogen sulfide content of the steam, e.g., 50 percent, . . . ". Neither the extent of CO.sub.2 uptake or the mols of NaOH consumed per mole of H.sub.2 S absorbed can be deduced from the data given.
Thus, the prior art gives no indication that substantially more than about 50% of the H.sub.2 S content of geothermal steam (which also contains substantial amounts of CO.sub.2) can be removed by alkaline scrubbing. This is particularly so with regard to steam produced from the Geysers area, where only about 0.18 pound of process water per pound of steam is available.